When a well, specifically an oil or gas well, has been completed and is yielding the desired product it is necessary to monitor the well's performance to ensure that it is behaving as expected. In particular, it is desirable to measure the rate at which the well's products--in an oil well, for example, these would be oil, water, gas or a combination, even a mixture, of all three--are flowing along the borehole and up to the surface, and it is generally desirable to monitor the flow velocities actually down the well itself rather than merely when they reach the surface. Many types of method and apparatus have been proposed for this purpose; two typical such involve firstly the use of a mechanical "spinner" and secondly the use of tracer or marker materials. In the spinner case a wireline-supported tool carrying a small propeller- (or turbine-) driven dynamo is placed in the flowing fluid so that the propeller is turned around by it, and the dynamo's output indicates the flow velocity. In the tracer/marker case there is used an injector/detector tool, by which a suitable material--for example, a detectable chemical or a radioactive substance--is injected into the fluid, and its arrival time at a downstream detector station is noted, giving the flow velocity by a simple distance-over-time calculation. Spinners work satisfactorily in borehole sections that are vertical, but not nearly so effectively in sections which are horizontal--it is common these days for a well to include a section driven horizontally through the underground geological formation delivering the sought-after product--for in such a section the well fluid is liable to be stratified into individual component layers (with the heaviest, such as water/brine, on the bottom, the lightest, such as methane gas, on the top, and any others, such as oil, in the middle), and these layers are not necessarily flowing at the same speed. A spinner placed in the borehole across two differently-flowing layers is therefore likely to output a signal which is at best some sort of average, and is at worst quite meaningless. For fluid flow velocity measurement in horizontal wellbore sections, therefore, it has been suggested that there should be employed tracer/marker materials and the appropriate injector/detector tools, and it is with this that the present invention is concerned.
There are many specific techniques utilising tracer/marker materials. For example, in a group of methods that might be referred to as "nuclear" there can be involved: radioactive substances, and detecting the radiation they emit; activatable substances, that on exposure to a radiation source become unstable, and detecting their decay products; neutron-absorbing substances, and detecting the fall in received neutrons from a source as the tracer passes by; and X-ray-absorbing (that is, dense) substances, and detecting the way they modify the radiation received from some appropriate X-ray source. Numerous techniques and materials have been previously proposed in the literature for use in monitoring flows in oil wells, and reference is made to the patents and technical literature.
However, regardless of what specific technique is employed, there remains the problem of measuring the flow velocity of the desired component of the wellbore fluid, and in part this is usually done simply by preparing the tracer/marker material that is significantly more soluble--or, at least, more miscible--in the chosen component than it is in the other(s). Thus, for monitoring a well's water/brine output the selected material is conveniently formulated as an aqueous solution, while an oil-miscible composition is used if it is the well's oil output that needs to be observed. All that is then left is for the tracer/marker composition to be inserted into the well fluid at the selected part of the horizontal section in such a way that it ends up in the desired component layer, and in the past this has been achieved merely by introducing the composition into the fluid somewhere across the borehole, and allowing it to migrate to its intended target. Thus, if injected into the bottom, aqueous layer, an aqueous tracer composition naturally stays there, while an oil-soluble composition is immiscible with (and lighter than) this bottom water layer and might be expected to rise up to and through the water/oil interface and so into the targeted oil layer. And, in theory, vice versa; injected into the upper, oil layer the oil-miscible composition stays there, while the water-based one migrates across the interface into the bottom, aqueous layer.
Unfortunately, and despite what seems to be accepted wisdom in the published literature about the theory of this technique, the Applicants have discovered through laboratory experiments that in practice the passage of the composition through the interface is in either case extremely difficult if not actually impossible, and that the assumptions made in this field about tracer migration in a miscible phase are simply, and unexpectedly, wrong. More specifically, either the passage of the composition through the interface is subject to some indeterminate delay or, and worse, the composition, having passed through the interface, is poorly (if at all) absorbed into the component. This is especially so if the composition materials can themselves become particulate and coated with the wrong (in this case, aqueous) layer component; as will be appreciated, such a delay , or such a poor absorption, causes either the flight time or the concentration of the tracer between injection and detection points to be unrepresentative of the speed or volume of the selected layer, and thus the estimated flow velocities/rates of the respective fluid phases can be substantially incorrect. The problem is discussed further hereinafter with reference to FIGS. 4a-h of the accompanying Drawings.
As might be expected, it is not normally acceptable to monitor the flow velocity of only one component layer in a horizontal borehole section, for much useful information can be gained by effectively simultaneously looking at all the layers. Nor is convenient to make use of tracer-injection equipment that has to be orientated one way for injecting the tracer composition into one layer and then re-oriented before it can be used to inject a second tracer composition into a second layer. It is therefore highly desirable to employ means for introducing the relevant tracer compositions that can, without intermediate re-orientation, in fact inject two (or more) different layers with the relevant tracer compositions, and even be able to inject them simultaneously. It is such a flow-monitoring, injection tool that the invention proposes. More specifically, the invention suggests an injection tool that comprises a plurality of spaced ejection ports (from which the relevant tracer composition can be ejected so as to be injected into the relevant chosen component layer), together with orientation means whereby in use the orientation of the tool can be so adjusted that the ports are so disposed as concurrently to lie each within the appropriate layer. Naturally, each port will be operatively connectable to a source of the relevant tracer composition from which will in use be supplied the amount to be injected; most conveniently the source will be the combination of a reservoir and a syringe-like device (which latter can draw a suitable amount of the composition from the reservoir and then drive it to, and eject it from, the associated port into the chosen layer).